Electric submersible pump (ESP) systems are typically installed in oil and gas wells where reservoir pressure is inadequate to lift reservoir fluids to the surface or to increase production in natural producing wells. As a reservoir is produced, the pressure in the pore space of the rocks decreases, and thus may require the introduction of some type of artificial lift system to continue production as a reservoir or a well ages. An ESP system provides an artificial lift for a reservoir and/or well and comprises a motor to convert electrical power from a cable to mechanical power to drive the pump.
While operating the powered devices associated with an ESP system in a downhole environment, it is important to make accurate and real time measurements of operational properties associated with the downhole device and its surroundings. Accurate monitoring of these operating parameters can help ensure reliable operation and can allow for the detection of problems with the system from the surface. When operating an electric submersible pump it can be beneficial to monitor properties associated with the fluid surrounding the pump and also the temperature and vibrations within the ESP system. In most operating environments, it can be critical to monitor the temperature of the ESP motor, because overheating of the motor can greatly affect the performance and durability of the device and can cause damage to vital electrical circuits and sensors.
Referring now to FIG. 1, a prior art ESP system is shown comprising pump 16 and motor 8, which drives pump 16. Power from a power line located externally of production tube 17 is connected to motor 8 by way of wet connect 15. Sealing means 18 are provided between the pump and the production tube 17 so the flow path of produced fluids is into the pump inlet 20 and out through the pump outlet beyond the sealing means 18 and upwardly toward the surface. An electronic sensor system (ESP gauge) 2 is typically provided with an ESP system and includes sensors configured to measure and monitor the fluid properties in the well in addition to the operating properties of the motor. By monitoring characteristics of the motor such as the operating temperature, pressure and vibration, the operation of the motor can be controlled to prevent overheating, failure or operating conditions that would shorten its life. In the typical configuration, the gauge is connected to the motor by way of capillary tubes (not shown) that house the electrical connecting leads for transmitting the sensed information pertaining to temperature, pressure, vibration, or other operating parameters of the motor. These capillary tubes are typically routed along the wet connect portion of the tubing string and are housed within grooves in the ESP system housing to protect the tubes and connecting leads from damage during deployment and use. With the gauge 2 located downhole from the motor 8 as shown in this arrangement, the capillary tubes and cabling must pass around the wet connect module 15 in order to connect the ESP motor with the sensor device. Accordingly, the location and configuration of these capillary tubes and cabling make the manufacture, deployment and maintenance of the sensor system difficult and are a significant source of damage, failure or malfunction.
Additionally, the location of the gauge at a position spaced away from the motor may introduce unreliability and error into the task of obtaining, monitoring, or processing sensor information that is indicative of motor performance and wellbore conditions. Therefore, any advance that could provide for a more reliable and protected manner of connection for the ESP system sensor equipment located within the gauge would provide a competitive advantage.